To explore for oil and gas, operators drill a well by rotating a drillstring having a drill bit and drill collars to bore through a formation. In a common form of drilling called rotary drilling, a rotary table or a top drive rotates a drillstring, which has a bottom hole assembly (BHA). The drillstring is rotated with increased weight to provide necessary weight on the assembly's bit to penetrate the formation. During the drilling operation, however, vibrations occurring in the drillstring can reduce the assembly's rate of penetration (ROP). Therefore, it is useful to monitor vibration of the drillstring, bit, and BHA and to monitor the drilling assembly's rate of rotation to determine what is occurring downhole during drilling. Based on the monitored information, a driller can then change operating parameters, such as weight on the bit (WOB), drilling collar RPM, and the like, to increase drilling efficiency.
Because the drillstring can be of considerable length, it can undergo elastic deformations, such as twisting, that can lead to rotational vibrations and considerable variations in the drill bit's speed. For example, stick-slip is a severe torsional vibration in which the drillstring sticks for a phase of time as the bit stops and then slips for a subsequent phase of time as the drillstring rotates rapidly. When it occurs, stick-slip can excite severe torsional and axial vibrations in the drillstring that can cause damage. In fact, stick-slip can be the most detrimental type of torsional vibration that can affect a drillstring.
For example, the drillstring is torsionally flexible so friction on the drill bit and drilling assembly as the drillstring rotates can generate stick-slip vibrations. In a cyclic fashion, the bit's rotational speed decreases to zero. Torque on the drillstring increases due to the continuous rotation applied by the rotary table, and the torque accumulates as elastic energy in the drillstring. Eventually, the drillstring releases this energy and rotates at speeds significantly higher than the speed applied by the rotary table.
The speed variations can damage the BHA, the bit, and the like and can reduce the drilling efficiency. To suppress stick-slip and improve efficiency, prior art systems, such as disclosed in EP 0 443 689, have attempted to control the speed imparted at the rig to damp any rotational speed variations experienced at the drill bit. Other systems monitor wear of a drill bit during drilling. For example, two particular examples of systems using multiple accelerometers on a drill bit to monitor wear of the bit are disclosed in U.S. Pat. Nos. 8,016,050 and 8,028,764.
In whirl vibrations (also called bit whirl), the bit, BHA, or the drillstring rotates about a moving axis (precessional movement) at a different rotational velocity with respect to the borehole wall than what the bit would rotate about if the axis were stationary. Forward whirl is when the drilling assembly precesses clockwise about the centerline of the borehole; and backward whirl is when the drilling assembly precesses counter-clockwise about the centerline of the borehole. Thus, in backward whirl, for example, friction causes the bit and BHA to precess around the borehole wall in a direction opposite to the drillstring's actual rotation. For this reason, backwards whirl can be particularly damaging to drill bits. Whirl can be extremely damaging to drilling collars and assemblies due to the high frequency bending stresses induced in the drillstring. These bending loads occur at a multiple of the string rotation rate and thus can be extremely detrimental to fatigue life. Whirl is self-perpetuating once started because radial and tangential acceleration create more friction. Once whirl starts, it can continue as long as bit rotation continues or until some hard contact interrupts it.
As noted above, stick-slip and bit whirl during drilling operations cause inefficiencies and can lead to failure of components downhole. An additional detrimental phenomenon is torsional vibration and torsional resonance of a drillstring or BHA. For example, effects of torsional resonance on drill collars having PDC bits in hard rock are discussed in SPE 49204, by T. M. Warren, et al. and entitled “Torsional Resonance of Drill Collars with PDC Bits in Hard Rock.”
When detrimental vibrations occur downhole during drilling, operators want to change aspects of the drilling parameters to reduce or eliminate the vibrations. If left unaddressed, the vibrations will prematurely wear out the bit, damage the BHA, or produce other detrimental effects. Typically, operators change the weight on bit, the rotary speed (RPM) applied to the drilling string, or some other drilling parameter to deal with vibration issues. Thus, the instantaneous diagnosis of detrimental vibrations can enable drilling operations to take timely corrective action to mitigate or stop the vibrations.
Unfortunately, existing data collection may not give a complete understanding of what is occurring to the drilling assembly downhole. Attempts to detect vibrations during drilling have historically used accelerometers in a downhole sensor sub to measure accelerations during drilling and to analyze the frequency and magnitude of peak frequencies detected.
As will be appreciated, the accelerometers in the downhole sensor sub are susceptible to spurious vibrations and can produce a great deal of noise. In addition, some of the mathematical models for processing accelerometer data can involve several parameters and can be cumbersome to calculate in real-time when a drilling operator needs the information the most. Lastly, the processing capabilities of hardware used downhole can be somewhat limited, and telemetry of data uphole to the surface may have low available bandwidth.
Existing systems typically obtain a bias for an accelerometer mounted off axis on a toolstring and subtract that bias as an average from the readings obtained by the accelerometer. During rotational drilling operations, however, the accelerometer conventionally mounted off axis is susceptible to radial and tangential acceleration that cannot be differentiated from true lateral vibrations. Torsional vibrations can occur downhole at such high frequencies that they may not be measurable using conventional data acquisition methods. This makes determining vibration of a downhole tool during drilling operations particularly difficult.
Several solutions to these problems are disclosed in U.S. Pat. Pub. 2013/0092439 and entitled “Analysis of Drillstring Dynamics Using an Angular Rate Sensor,” which is incorporated herein by reference in its entirety. In these solutions, an angular rate gyroscope is used off-axis on a tool of a drillstring to directly measure the angular acceleration and angular velocity—components of angular motion—which can then be analyzed to determine the vibration occurring downhole. Although this is effective, operators strive for additional ways to measure angular and linear motion to determine vibrations of a tool downhole during drilling. It is to this end, at least in part, that the subject matter of the present disclosure is directed.